Subterranean drilling systems that employ downhole drilling motors are commonly used for drilling boreholes in the earth for oil and gas exploration. FIG. 1 is a schematic isometric partial cross-sectional view of a prior art subterranean drilling system 100. The subterranean drilling system 100 includes a housing 102 enclosing a downhole drilling motor 104 (i.e., a motor, turbine, or any other device capable of rotating a shaft) that is operably connected to an output shaft 106. A thrust-bearing apparatus 108 is also operably coupled to the downhole drilling motor 104. A rotary drill bit 112 configured to engage a subterranean formation and drill a borehole is connected to the output shaft 106. The rotary drill bit 112 is shown as a roller cone bit including a plurality of roller cones 114. However, other types of rotary drill bits, such as so-called “fixed cutter” drill bits are also commonly used. As the borehole is drilled, pipe sections may be connected to the subterranean drilling system 100 to form a drill string capable of progressively drilling the borehole to a greater depth within the earth.
The thrust-bearing apparatus 108 includes a stator 116 that does not rotate and a rotor 118 that is attached to the output shaft 106 and rotates with the output shaft 106. The stator 116 and rotor 118 each include a plurality of bearing elements 120 that may be fabricated from polycrystalline-diamond compacts that provide diamond bearing surfaces that bear against each other during use.
In operation, high pressure drilling fluid is circulated through the drill string and power section (not shown) of the downhole drilling motor 104, usually prior to the rotary drill bit 112 engaging the bottom of the borehole, to generate torque and rotate the output shaft 106 and the rotary drill bit 112 attached to the output shaft 106. Unless rotated from above by the drill rig rotary, the housing 102 of the downhole drilling motor 104 remains stationary as the output shaft 106 rotates the rotary drill bit 112. When the rotary drill bit 112 engages the bottom of the borehole, a thrust load is generated, which is commonly referred to as “on-bottom thrust” that tends to compress the thrust-bearing apparatus 108. The on-bottom thrust is carried, at least in part, by the thrust-bearing apparatus 108. Fluid flow through the power section may cause what is commonly referred to as “off-bottom thrust,” which is carried, at least in part, by another thrust-bearing apparatus that is not shown in FIG. 1. The drilling fluid used to generate the torque for rotating the rotary drill bit 112 exits openings formed in the rotary drill bit 112 and returns to the surface, carrying cuttings of the subterranean formation through an annular space between the drilled borehole and the subterranean drilling system 100. Typically, a portion of the drilling fluid is diverted by the downhole drilling motor 104 to cool and lubricate both the thrust-bearing apparatus 108 and the other thrust-bearing apparatus.
Both the off-bottom and on-bottom thrust carried by the thrust-bearing apparatuses can be extremely large. Accordingly, the operational lifetime of the thrust-bearing apparatuses often determines the useful life for the subterranean drilling system 100. For example, despite diamond having a relatively high wear resistance, repetitive contact between the bearing elements 120 of the stator 116 and the rotor 118 during drilling can cause the bearing elements 120 to wear and, eventually, fail. Moreover, even though the diamond bearing surfaces of the bearing elements 120 may have a fairly low coefficient of friction, frictional contact between the diamond bearing surfaces of the stator 116 and the rotor 118 can still lower the operational efficiency of the subterranean drilling system 100 due to frictional losses. Therefore, manufacturers and users of subterranean drilling systems continue to seek bearing apparatuses with improved wear resistance and efficiency.